The invention generally relates to determining elastic and fluid flow properties of a fractured reservoir.
Natural fractures in reservoirs play an important role in determining fluid flow during production, and hence, knowledge of the orientation and density of fractures typically is vital in order to optimize production from naturally fractured reservoirs. Areas of high fracture density can represent “sweet spots” of high permeability, and it is typically important to be able to target such locations for infill drilling. The fractures with the largest apertures at depth tend to be oriented along the direction of the maximum in-situ horizontal stress and may therefore lead to significant permeability anisotropy in the reservoir. This will lead to an anisotropic permeability tensor, and it typically is important for optimum drainage that the separation of producers should be more closely spaced along the direction of minimum permeability than along the direction of maximum permeability.
Because oriented sets of fractures also lead to direction-dependent seismic velocities, information obtained in a seismic survey may be used to determine the orientations of fractures. Reflection amplitudes offer advantages over the use of seismic velocities for characterizing fractured reservoirs since they have higher vertical resolution and are more sensitive to the properties of the reservoir. However, the interpretation of variations in reflection amplitudes requires a model that allows the measured change in reflection amplitude to be inverted for the characteristics of the fractured reservoir.
Conventionally, models that are used to describe the seismic responses of fractured reservoirs have made simplified assumptions that prevent fractured reservoirs from being characterized correctly. In this manner, conventional models typically assume a single set of perfectly aligned fractures. However, most reservoirs contain several fractures sets with variable orientations within a given fracture set.
The use of a model that assumes a single set of fractures may therefore give misleading results. For example, for a vertically fractured reservoir containing a large number of fractures with normals being isotropically distributed in the horizontal plane, there is little or no variation in the reflection coefficients with azimuth. Therefore, an interpretation of the reflection amplitude versus azimuth curve based on the single set of aligned fractures assumption would predict incorrectly that the fracture density is zero.
Thus, there is a continuing need for a better way to model the seismic response of a fractured reservoir.